Method of using a surface jet pump to mitigate severe slugging  in pipes and risers

ABSTRACT

A slug mitigation system for subsea pipelines that includes a riser located between a low subsea level and an upper topside level of a pipeline. There is also a separator located at the top of the riser; and a surface jet pump located at a gas outlet of the separator. In another embodiment of a slug mitigation system, the surface jet pump is located downstream of an in-line separator on a gas outlet using high pressure gas from a downstream process or compressor.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims foreign priority benefits under 35 U.S.C.§119(a)-(d) to GB 1420234.5 filed Nov. 14, 2014 which is incorporated byreference in its entirety and relied upon.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to improved arrangements for slugmitigation in subsea pipelines, such as risers, as used in the oil andgas industry and particularly, according to the invention, utilising asurface jet pump (SJP) apparatus in such arrangements. It is also hopedthe invention will boost production.

2. Description of Related Art

Most of the new discoveries of oil and gas reserves are being foundfurther offshore, causing operators to delve further and deeper into theseabed. The transportation of production fluids to offshore platforms(for processing and further export) requires subsea pipelines followedby a vertical pipe to the platform; also known as a riser-pipelinesystem. The combination of such pipe configurations invariably cause a‘low-point’, which encourages an undesired multiphase flow regime knownas Severe Slugging (SS). From the flow assurance point of view, thispressure oscillation phenomenon is of particular concern for maturewell/fields which have a declining operating pressure. This phenomenonalso upsets top side operation of process facilities and introducesvibration in the riser piping system, leading to a possible mechanicalfailure.

There are a number of approaches being developed/deployed to mitigatesevere slugging issues. For example:

On the top side of the platform:

-   Installing a control valve at the top of riser to impose back    pressure-   Making a gravity separator bigger during the initial stage of design-   Installing a large liquid slug catcher upstream of existing    production separator (another gravity separator)

Bottom of riser (Subsea):

-   Inject gas at the bottom of the riser to lighten static head-   Install an additional riser and send flow through both risers-   Perform subsea separation and use two risers for sending gas and    liquids

BRIEF SUMMARY OF THE INVENTION

The present invention seeks to find a system that mitigates a severeslugging regime in a passive way without the need of active controlwhilst reducing the imposed back pressure on the wells (through processequipment, riser and connecting piping) also resulting in a higherproduction for the operator.

The current invention looks at the process role and location of aSurface Jet pump in the following way:

-   To gain additional production/pressure boost, and also to drive weak    backed out low pressure (hereinafter “LP”) wells in production mode-   As an added advantage, mitigate severe slugging in risers-   Changing the flow regime in the piping system to be more favourable    and creating a mixture flow of lower design (than an all liquid    case)-   Stabilising production-   Minimise flow oscillation and vibration in the riser-   Expanding gas reduces the static head imposed by vertical liquid    column in the riser-   Improve the severe slugging stabilised operating region-   Minimise liquid dropout pooling in the low points in the pipeline    (due to increase gas velocity and sweep velocity)-   Effective use of injection gas, which is currently used for liquid    static head lightening

Surface jet pumps (SJPs) are generally known in the art. Drawing on theexperience gained in the use of an SJP on a wellhead and separators,i.e. in how reducing back pressure helps increase the flow through awell, even for gas lifted oil wells (refer to patent applicationWO2013124625A2), the current invention is suggested for reducing severeslugging.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates an example where an SJP is located on the top of theriser at the platform;

FIG. 2 illustrates an example where an SJP is located on the top of theriser at the platform on the gas outlet of the production separator;

FIG. 3 illustrates an example where an SJP is located on the top of theriser at the platform upstream of the production separator on the riser;

FIG. 4 illustrates an example where an SJP is located on the top of theriser at the platform upstream of the production separator on the riser;

FIG. 5 illustrates an example where an in-line separator (I-Sep) is usedto mitigate severe slugging effects in a riser;

FIG. 6 shows a commonly used prior art approach for severe slugmitigation in a subsea environment; and

FIG. 7 illustrates a modification to the gas injection approach of FIG.6 at the riser base by introducing a subsea SJP.

DETAILED DESCRIPTION OF THE INVENTION

SJP Applications to reduce severe slugging are described in detailbelow. In particular, with reference to FIG. 1, an SJP is located on thetop of the riser at the platform. The SJP can be powered by an availablehigh pressure fluid source—either liquid phase or gas phase. The SJPwill lower the backpressure (arrival pressure) at the top of the riserwhich will in turn reduce the back pressure in the riser, allowing gasto expand in the riser/pipe lines. This action will change the operatingflow regime and minimise the severe slugging region within riser. Theback pressure reduction will also allow the LP wells to produce more(based on their flow and pressure relationships), which is a benefit tothe operator. If production is mainly from gas wells with some liquidsthen the SJP can be powered by the high pressure (hereinafter “HP”) gasstream. If LP well production is from mainly liquid wells, then the SJPcan be powered by HP liquids. The outlet of SJP can go to an export linedirectly or to a downstream production separator.

FIG. 2: An SJP is located on the top of the riser at the platform on thegas outlet of the production separator. The SJP is powered by the HP gasavailable from the export compressor outlet or from its recycled gasstream. The SJP will lower the production separator pressure which willallow backpressure reduction and change of flow regime in the riser andpiping. Additional benefit would be backpressure reduction on theproduction manifold, leading to increase production on the same well.This increased production also adds in shifting severe slugging regiontowards a stabilised flowrate. In this application regardless of thetype of production (gas dominated or liquid dominated), the gas drivenSJP will be applicable to ease of severe slugging issues and allowadditional production too.

FIG. 3: An SJP is located on the top of the riser at the platformupstream of the production separator on the riser. The SJP is powered bythe HP gas available from the export compressor outlet or from itsrecycled gas stream. The riser flow can be diverted via the SJP in fullor in part as per control requirement of the operator. The HP gas mixeswith the riser fluid and goes as a low density mixture into the gravityseparator. At the same time, the SJP also act as back pressure reduceron the riser to achieve benefits already highlighted for FIGS. 1 and 2.Depending on the location of the SJP on the riser itself the lightdensity mixture can be created at various heights in the riser (thiswill also reduce the static head in the riser fluid column) and createstabilised flow within riser.

FIG. 4: An SJP is located on the top of the riser at the platformupstream of the production separator on the riser. The SJP is powered bythe liquid pump using the part of the produced liquid as the HP source.This approach is also applicable in situations where no spare HP gas isavailable for the SJP. The riser flow can be diverted via the SJP infull or in part based on the control requirement of the operator. Theoutlet from the SJP enters as a well mixed gas/liquid mixture into thegravity separator. At the same time, the SJP also act as back pressurereducer on the riser to achieve benefits already highlighted for FIGS. 1and 2. Due to additional liquid in the piping system the operatingpressure of the separator/riser may rise, however, in this situation,the SJP will discharge flow at a higher pressure as required by thedownstream process (separator, piping, etc.) while still maintaining thebackpressure reduction on the riser to affect the severe slugging andincrease production from the existing infrastructure.

FIG. 5: This option explores the ability of an in-line separator (I-Sep)to mitigate severe slugging effect in a riser as discussed in detailelsewhere (e.g. our co-pending patent application No. GB 1419947.5 whichis incorporated herein by reference). We have suggested using SJP on thegas outlet using HP gas from the downstream process (compressor). Thefunction of SJP would be the same as discussed above, mainly reducingback pressure to change flow regime in the riser and also to gainproduction from wells. In such case, the main production separator canbe by-passed or operated in parallel with the I-SEP/HI-SEP system. Theproduced gas can go to the gas outlet and produced liquid will join theliquid line upstream of the liquid pump. The use of SJP with I-SEP willenhance the severe slug mitigation capability over the one alreadydiscussed in our co-pending patent application using I-SEP for slugmitigation.

FIG. 6 (Prior Art): This shows commonly used approach for severe slugmitigation in subsea environment, in which high pressure gas from theplatform is injected at the base of the riser. This serves two mainfunctions, first of all to reduce the mixture density of the liquidcolumn in the riser, hence reduces the backpressure on the productionline wells, secondly it changes the flow regime in the riser, so thatsevere slugging is mitigated. The issues of this approach is that due toextra gas in the system the topside separator pressure increases, whichnegate some of the back pressure reduction gained by lightening thestatic liquid head. Also this does not allow additional backpressurereduction on the wells to gain production the way SJP does.

FIG. 7: In this concept, we have modified the gas injection approach ofFIG. 6 at the riser base by introducing a subsea SJP. The SJP will giveadded benefit of overcoming the incremental pressure rise at the inletof topside separator (and in the riser) due to addition of HP gas. Itwill also allow back pressure reduction on the LP wells for maintainingor gaining additional production. It will also minimise any severeslugging effect while reducing the static head in the riser. The HP gasto power the SJP can come from the platform. Again, either part or fullproduction can be diverted through the SJP as needed.

If there is no HP source available at the platform and there is a nearbysubsea HP pressure manifold, then using this HP pressure energyadditional backpressure reduction on the LP well can also be achievedvia the SJP, while still keeping the benefits of severe sluggingmitigation in the riser. Gas injection at the bottom of riser does notoffer these stated benefits.

What is claimed is:
 1. A slug mitigation system for subsea pipelinesincluding: a riser located between a low sub-sea level and an uppertopside level of a pipeline; a separator located at the top of theriser; and a surface jet pump located at a gas outlet of the separator.2. The slug mitigation system of claim 1 wherein the surface jet pump ispowered by high pressure gas available from an export compressor outletor from its recycled gas stream.
 3. A slug mitigation system for subseapipelines including: a riser located between a low sub-sea level and anupper topside level of a pipeline; a surface jet pump located at theupper topside level of the pipeline, downstream of the riser; whereinthe surface jet pump is located downstream of an in-line separator on agas outlet using high pressure gas from a downstream process orcompressor.
 4. The slug mitigation system of claim 3 wherein a mainproduction separator at the top of the riser can be by-passed oroperated in parallel with the inline separator and surface jet pump. 5.The slug mitigation system of claim 3 wherein produced gas can go to agas outlet and produced liquid joins the liquid line upstream of aliquid pump.